In connection with the completion of oil and gas wells, it is frequently necessary to utilize packers, plugs, liner hangers, and the like in both open and cased boreholes for a number of reasons. For example, when fracturing a hydrocarbon bearing formation, a section of the well may be isolated from other sections of the well so fluid pressure can be applied to the isolated section while protecting the remainder of the well from the applied pressure.
In a staged fracturing operation, for example, multiple zones of a formation need to be isolated sequentially for treatment. To achieve this, operators install a fracture assembly as shown in FIG. 1A in a wellbore 10, which may have casing 12 and perforations 14. Typically, the assembly has a top liner packer (not shown) supporting a tubing string 16 in the wellbore 10. Packers 50 on the tubing string 16 isolate the wellbore 10 into zones 18A-C, and various sliding sleeves 20 on the tubing string 16 can selectively communicate the tubing string 16 with the various zones 18A-C.
The packers 50 typically have a first diameter to allow the packer 50 to be run into the wellbore 12 and have a second radially larger size to seal in the wellbore 12. The packer 50 typically consists of a mandrel 52 about which a sealing element 58, slips 54, cones 56, and the like are assembled.
Other downhole tools are also used for isolating a wellbore and have a mandrel about which a sealing element, slips, cones, and the like are assembled. For example, a plug 50 as shown in FIG. 1B can be placed within a wellbore 10 to isolate upper and lower sections of production zones. The plug 50 includes a sealing element 58, slips 54, and cones 56 on a mandrel 52. When set, the plug 50 creates a pressure seal in the casing 12 of the wellbore 10, which allows pressurized fluids to treat an isolated zone of the formation, such as through perforations 14 in the casing 12.
On packers, plugs, and other downhole tools, the sealing elements 58 are typically composed of an elastomeric material, such as rubber. When the sealing element 58 is compressed in one direction it expands in another. Therefore, as the sealing element 58 is compressed longitudinally, it expands radially to form a seal with the well or casing wall.
The slips 54 used on the downhole tool 50 prevent movement of the sealing element 58 and the production string 16 or tool 50 during hydraulic stimulation. Two slips 54 are often employed in situations where the downhole tool 50 may need to hold pressure from above and below the sealing element 58. In uni-directional pressure applications, such as fracturing, two slips 58 are still used to prevent excessive build-up of rubber pressure leading to a collapse of the tool's mandrel 52.
For example, FIG. 2A illustrates a traditional slip configuration 60 according to the prior art for a downhole tool 50 (e.g., a packer, plug, etc.). A mandrel 52 of the downhole tool 50 has a lower sub or shoulder element 62b affixed at one end. The opposite end has a support or push ring 62a acting as an opposite shoulder element. Between these shoulder elements 62a-b, the mandrel 52 has a sealing element 68 surrounded by opposing cones 66a-b. Finally, a pair of opposing slips 64a-b are disposed outside the cones 66a-b. 
During run-in of the tool 50 through tubing 15 (e.g., casing, or the like), the shoulder elements 62a-b are spaced apart, the slips 64a-b lay retracted against the mandrel 52, and the sealing element 68 is uncompressed. When the tool 50 reaches a desired depth in the tubing 15, the tool 50 can be set as shown in FIG. 2B. To set the tool 50, the shoulder elements 62a-b are moved toward one another, either by holding the support 62a while pulling the sub 62b with the mandrel 52, by holding the mandrel 52 with its sub 62b while pushing on the support 62a, or by performing a combination of these actions.
When deployed downhole, for example, the tool 50 can activated by a setting tool 70. During setting, the slips 64a-b ride up the cones 66a-b and set against the tubing 15. In the meantime, the cones 66a-b move along the mandrel 52 toward one another and compress the sealing element 68. Finally, the compressed sealing element 68 expands outward against the tubing 15 to create a seal in the annulus between the mandrel 52 and the tubing 15. In general, the upper slip 64a is used to hold against slippage from downhole pressure, while the lower slip 64b is used to hold against slippage from uphole pressure.
During operations, operators may close off the through-bore 54 of the tool's mandrel 52 so that pressure can be applied uphole of the tool 50. Communication past the tool 50 between the mandrel 52 and tubing 15 is prevented by the sealing element 58. As shown in FIG. 2C, a ball B deployed to the tool 50 engages a seat 56 in the mandrel's through-bore 54. With the ball B seated, the tool 50 isolates upper and lower portions of the tubing 15 so that fracture and other operations can be completed uphole of the tool 50, while pressure is kept from downhole locations.
As shown in FIG. 2C, pressure applied against the seated ball B tends to push against the mandrel 52. The anchored slips 64a-b, cones 66a-b, and sealing element 68 can remain engaged with the tubing 15, but may be allowed to slide along the mandrel 52. For example, the mandrel 52 may be pushed further through the anchored slips 64a-b, cones 66a-b, and sealing element 68 at least until the mandrel 52 shoulders out against the support 62a. 
The pressure (force) applied against the seated ball B passes to the mandrel 52 through the seat 56 and then passes through the anchored upper slip 64a and cone 66a. At this point, a portion of the boost load is directed into the tubing 15. The boost load then passes through the set sealing element 68, and then through the lower cone 66b and slip 64b. Eventually, the remaining pressure (force) extends to the tubing 15 from the lower slip 64b. 
The force acting through the anchored components 60 forces the sealing element 68 further against the mandrel 52. At some point, the mandrel 52 can collapse due to the boost force applied about the mandrel's circumference. This form of mandrel collapse due to a sealing element's pressure on a tool 50, such as packers and plugs with slips, has traditionally been addressed by using an expansion joint, using a dual slip system as shown in FIGS. 2A-2C, or using a bi-directional slip.
Various types of downhole tools, such as packers and plugs, having slip configurations are known in the art. For example, Weatherford's Ultrapak and Optipak packers use either opposing uni-directional slips or use a bi-directional slip. Weatherford's composite fracture plugs use two opposing uni-directional slips and have a smaller through-bore so the mandrel can withstand high pressures. Other downhole tools include the removable bridge plug or packer disclosed in U.S. Pat. No. 6,167,963 and the Shadow Series Frac Plug available from Baker Hughes Incorporated.
The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.